During the upper completion process on subsea drilled and lower completed wells, the tubing hanger, which suspends the production tubing in the subsea production tree, is locked into the tree or wellhead. Numerous time-consuming operations such as flowing back the well, testing the well, testing the intelligent well equipment, plugging the well, etc. can occur after the tubing hanger is locked in place. These operations occur from a floating rig which heaves (moves up and down) with the sea waves and currents. The floating rig must rely on its derrick based compensation system during this period when the tubing hanger, tubing, and associated equipment are locked into a stationary structure, such as the tree or wellhead, on the seafloor. The tubing hanger and associated equipment can be over-stressed, damaged or even pulled apart if the compensation system fails when the rig moves. Further, the process of landing the tubing hanger is difficult, as it must be done fairly delicately and, once landed, it may be necessary to keep the landing tool in place for several days.
Compensation systems can be active or passive. Active systems, such as are effected through the rig drawworks or top drive, are powered by the rig, and passive systems are independent of rig power. The active compensation system will lose functionality when the rig loses power, while a passive system will continue to function during a power loss. Loss of heave compensation can cause stress and/or parting to the landing string and/or the associated running equipment. Most derrick based compensation systems that hold the tubing are actively compensated and, as such, a risk exists when the tubing running hanger tool is attached to a locked tubing hanger should a power loss condition occur.
As shown in FIG. 1, within a subsea well completion system 100, a passive compensated coil tubing lift frame (CCTLF) 102 can be installed into the derrick to hold the tubing at surface when installing the tubing hanger and locking it into the tree in order to mitigate risk. A CCTLF 102 has nitrogen filled cylinders that go up and down and provide passive heave compensation. A CCTLF 102 is typically installed for longer connection periods. A CCTLF 102 is a massive piece of equipment that is costly to install, test, and operate. A CCTLF 102 is suspended from the rig elevator and drawworks system incorporating ‘weak link bails’ designed to fail before encountering an overpull. Additionally, many operators will use a subsea test tree (SSTT) 104 internal to a subsea BOP 106 during the tubing hanger installation process. The SSTT 104 is operated by hydraulic lines, such as an inner umbilical 116, running on the outside of the landing string 108 to the sea surface and contains a set of valves. The landing string 108 runs on the inside of the marine riser 110. The subsea BOP 106 can be closed around the SSTT 104 allowing access of the choke and kill lines to the well at the subsea BOP 106. The SSTT 104 also has functionality to separate below the blind/shear rams 112 to allow disconnection from the subsea well 114 should the need arise. The SSTT 104 must be ‘in tension’ by locking the tubing hanger and applying an upward pull through the landing string 108, to function correctly. An in-riser umbilical or inner umbilical 116 can control downhole functions such as surface controlled subsurface safety valve (SCSSV), intelligent well completion accessories (IWC), and/or electrical submersible pump (ESP). An IWOCS umbilical 118 for installation and workover control system (IWOCS) runs outside of the riser and can convey temporary controls to the tree, to which downhole control and telemetry functions are transferred.
Current methods can take 10-12 days to simply run an upper completion into a well and land a tubing hanger in place. This long period of time is mostly due to the need for passive heave compensation. Thus, a new passive motion compensated assembly, system, and process for landing tubing can save time and reduce cost.